Energy Business UnitSeptember 4, 2018Kieron McFadyen, Senior Vice President, EnergyBrad Strueby, Director, OperationsGlenn Burchnall, Director, Marketing and Logistics
Forward Looking InformationBoth these slides and the accompanying oral presentations contain certain forward-looking statements within the meaning of the United States Private SecuritiesLitigation Reform Act of 1995 and forward-looking information within the meaning of the Securities Act (Ontario) (collectively referred to herein as forward-lookingstatements). Forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause the actual results, performance orachievements of Teck to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements.These forward-looking statements include statements relating to our resource and mine life estimates, including potential production from Frontier, timing of fullproduction at Fort Hills, debottlenecking opportunities, potential benefits and capacity increase from debottlenecking opportunities at Fort Hills and costs associatedwith debottlenecking, projected and targeted operating costs, projected life of mine sustaining capital costs, potential capacity increase at Fort Hills, potential forlonger term expansion opportunities at Fort Hills and associated costs, the expectation that Fort Hills will provide free cash flow for decades and a steady andreliable cash flow, Energy EBITDA potential, benefits of our marketing and logistics strategy and associated opportunities, and our expectations regarding ourinnovation and technology initiatives.
The forward-looking statements in these slides and accompanying oral presentation are based on assumptions regarding, including, but not limited to, generalbusiness and economic conditions, assumptions regarding the accuracy of our resource and mine life estimates and their underlying assumptions, assumptionsthat our Fort Hills project develops as contemplated by the partners, assumptions regarding receipt of governmental approvals for our development projects, ourcosts of production and productivity levels, conditions in the financial markets, the future financial performance of the company and our ongoing relations with ouremployees and business partners and joint venturers. Certain forward-looking statements are based on assumptions disclosed in the slides or footnotes to therelevant slides, including WTI price assumptions, WTI-WCS differentials, C$/US$ exchange rates and operating costs.
Factors that may cause actual results to vary materially include, but are not limited to, changes in commodity prices, inaccurate assumptions that form the basis forour resource estimates, unanticipated operational and development difficulties, government action or delays in the receipt of governmental approvals and issues inobtaining and maintaining permits. Fort Hills operating costs could be negatively affected by delays in or unexpected events involving the ramp-up ofproduction. Our economic projections and expectations for Fort Hills will be affected by, among other things, differences between actual WTI and assumed WTI,actual WTI-WCS differentials and assumed differentials, actual exchange rates and assumed exchange rates, and actual operating costs and assumed operatingcosts, as well as the actual price at which we sell our barrels. Our Fort Hills project is not controlled by us and construction and production schedules may beadjusted by our partners.
We assume no obligation to update forward-looking statements except as required under securities laws. Further information concerning assumptions, risks anduncertainties associated with these forward-looking statements and our business can be found in our most recent Annual Information Form, as well as subsequentfilings of our management’s discussion and analysis of quarterly results and other subsequent filings, all filed under our profile on SEDAR (www.sedar.com) and onEDGAR (www.sec.gov).
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Agenda
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Introduction to Teck Energy
Fort Hills
Energy Marketing & Logistics
Frontier Update
Next Generation Oil Sands Development
Summary
A Highly Focused TeamLeveraging Teck’s mining capability
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Scott McKenzieDirector, Regulatory & Environment
Robin JohnstoneGM, Community & Indigenous Affairs
Lyndon ChiassonDirector, Engineering
Yvonne WalshDirector, Community & Indigenous Affairs
Kieron McFadyenSenior Vice President, Energy
Brad StruebyDirector, Operations
In Attendance
Glenn BurchnallDirector, Marketing & Logistics
In Attendance
Rob SekhonController, Energy
In Attendance
In Attendance
Quality Barrels in a Progressive Jurisdiction4th largest oil sands mining portfolio
5
Fort Hills is in operation• Teck 21.3% = 0.6 billion barrels1
Frontier is in the regulatory phase• Teck 100% = 3.2 billion barrels2
Lease 421 is a future growth opportunity• Teck 50% • High quality lease: high grade, high recovery,
low fines
Alberta, Canada
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Energy Within Teck’s PortfolioConsistent with all our strategic criteria
Strategic diversification
Long life assets
Truck & shovel operations
Low unit operating costs
Resource quality & scale
Stable jurisdiction
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Our Energy StrategyTeck as a partner of choice
Focus on maximizing value of Fort Hills• Safe and efficient ramp-up, increase production volumes, lower costs
De-risk Frontier & Lease 421 • Frontier regulatory hearing scheduled for September 25, 2018
Drive business results through technology & innovation• Safe & reliable production, cost and footprint
Fort Hills
Fort Hills is a Premier AssetLong-life of >45 years with a very low decline rate
• Commissioning has exceeded our expectations, and full production expected by Q4 2018
• We won’t rest on our laurels; focus on unit costs & low capital intensity debottlenecking opportunities
• Executing our comprehensive sales & logistics strategy
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10
Lower Carbon Intensity Product at Fort HillsComparable to the average barrel refined in the U.S.
• Paraffinic Froth Treatment (PFT) removes asphaltenes• Best in-class Canadian oil sands carbon intensity, including in-situ• Pushing technology for continuous improvement
350400450500550600
Eagle FordTight OIl
Arab Light Bakken Blend Russian Urals MexicanMaya
Mining OilSand Dilbit
PFT (e.g. FortHills)
NigerianBonny Light
Oil Sand In-Situ dilbit
Oil SandMining
UpgradedSCO
AverageCalifornia
Heavy
PFT Diluted Bitumen has a Lower Carbon Intensity Than Around Half of the Barrels of Oil Refined in the US, on a Wells-to-Wheels Basis1
Carbon intensity of average barrel refined in the US = 502
Tota
l car
bon
inte
nsity
(kgC
O2e
pe
r bar
rel o
f ref
ined
pro
duct
s)
Source: IHS Energy Special Report “Comparing GHG Intensity of the Oil Sands and the Average US Crude Oil”, May 2014.
A Modern Mine Built for Low Cost OperationsProvides the foundation for our Energy business
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Safe & efficient operations:• Using leading-edge technology• Learnings from other facilities
Operating costs:• Life of mine cash operating costs: C$22-23/bbl1• Target below C$20 per barrel
Capital efficiency:• Life of mine sustaining capital: C$3-5/bbl2• Higher in 2019 due to tailings and equipment
ramp-up spending
12Reliability and Availability Modeling (RAM) will quantify the potential uplift
Significant Debottlenecking Potential at Fort HillsOpportunities identified during commissioning and start-up
Mining Ore Preparation
Primary Extraction
SecondaryExtraction
Debottlenecking and Expansion OpportunitiesWith significant incremental cash flow potential
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Potential capacity increase of 20-40 kbpd on a 100% basis• Teck’s 21.3% share of annual production could
increase from 14.0 Mbpa to 15.5-17.0 Mbpa
• Near term opportunities to achieve some of the increase with minimal capital
• Longer term opportunities may require modest capital
Free Cash Flow for DecadesProviding Teck with steady and reliable cash flow
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• Energy EBITDA potential of ~C$530M at full production of 14 Mbpa1
• Significant upside with debottlenecking
AssumptionsWTI price US$75/bbl
WTI-WCS differential US$14.75
C$/US$ exchange rate 1.25
Operating costs C$20/bbl
Energy Marketing & Logistics
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First sales in March 2018
Excellent acceptance of Fort Hills’ product (FRB) in our core markets
Active purchaser of diluent
Significant Market PresenceDeveloping a reputation as a preferred counterparty
Teck’s Commercial Activities1
Bitumen production 38.3 kbpd+Diluent acquisition 11.2 kbpd=Bitumen blend sales 49.5 kbpd
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Executing Our Comprehensive Sales & Logistics StrategySeeing early returns from diverse market access
Our sales mix provides diverse market access1
• 10 kbpd shipped to US Gulf Coast via Keystone pipeline
• 39.5 kbpd at Hardisty, a key Canadian market hub
Well positioned for future opportunities, including:• Rail loading capacity at Hardisty• Export pipeline expansions
20 kbpd
10 kbpd
19.5 kbpd
Sales MixLong term contracts
at Hardisty
Monthly basis at Hardisty
Monthly basis to US Gulf Coast
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US Midwest and US Gulf Coast are Key MarketsExcess capacity for heavy in North America
Key Markets:
• US Midwest is the largest market, but future growth is constrained
• US Gulf Coast has exceptional growth potential
Blended Bitumen PipelinesTeck has contracted capacity on the existing Keystone
pipeline and the proposed TransMountain pipeline
Enbridge/Enbridge Flanagan South
TransMountain
TransCanada Keystone, Keystone XL
Market Hub
Deep Water Port
In Service Pipeline
Proposed Pipeline
Hardisty or Common Carriage to Midwest / USGC
Cushing
Flanagan
HardistyEdmonton
Vancouver
Steele City
AsiaSuperior
Montreal
Asia/ Europe
California
0
500
1,000
1,500
2,000
2016 2020
kbpd
Additional Capacity Available for Canadian HeavyCanadian Heavy Usage
US Gulf Coast Heavy Blend Processing
Source: CAPP, Lee and Doma
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Long Term Alberta Logistics Capability in PlaceContracted capacity will accommodate production upside
East Tank FarmBlending Facility
Edmonton Terminal
Teck
Northern Courier Pipeline
Norlite Pipeline
Fort SaskatchewanCavern Storage
Fort Hills Mine Terminal
Teck
Pipeline Legend
BitumenDiluentProductsBlendTeck ContractedThird Party Shipper
FHELP Managed
Wood Buffalo Pipeline
Hardisty Terminal Keystone
US Gulf Coast
Enbridge MainlineUS Midwest, Eastern Canada
Rail Loading
Frontier Update
Frontier is Another Major Resource
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100% Teck
Nameplate capacity of 260,000 bpd
Resource of 3.2 billion barrels1
>40 year mine life
Frontier Hearing Commences September 25, 2018Strong community support
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Submitted Integrated Application November
2011
Joint Regulatory
Review
Project Update
SubmissionJune 2015
Joint Regulatory
Review
Provincial Completeness
Panel Appointment
May 2016
JRP Review
JRP Hearing
JRP Report
Federal Decision
Statement
We are Ready for the Next Phase Regulatory permitting process continues
We are leading:• One of most comprehensive environmental
assessments to date• Developing strong relationships with Indigenous
communities and other stakeholders • Recognized permitting and progressive mining
experience
What is next:• Final preparations ahead for the public hearing
this fall• Panel then produces report; Federal Decision
Statement anticipated by mid-2019
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Next Generation Oil Sands Development
Driving Business Results Technology/innovation sustains competitiveness and license to operate
Business Drivers:
• Operational excellence
• Unit cost savings
• Capital efficiency
• Environmental performance
• Safety
Technology/Innovation:
• Autonomous haul trucks
• Solvent extraction
• Debottlenecking
• Partial upgrading
• Leveraging existing assets
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Collaborating with the Industry as Part of COSIATechnology is king
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Canada’s Oil Sands Innovation Alliance (COSIA)
Drones
Teck’s Technology PipelineLevering our know-how & innovation
Implementing Piloting Scanning
Smart Shovel
AutonomousHaul
FinesAgglomerationCore
Scanning
Remote Dozer
Blast Movement
PredictiveMaintenance
VR / AR
Electrostatic dust field
Coarse Particle Flotation
FlotationMagnets
Diggability UX
Saturated Fill
Filtered Tailings
Note: Bubble size indicates potential value.
AlternativeMaterial Handling
Shovel Heads up Display
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Technology & Innovation at TeckWe put ideas to work
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Autonomous Haul Trucks• Improved productivity &
safety• Fort Hills is autonomous
ready• Six-truck deployment at
HVC by end of 2018
Operator Augmentation• Empowers shovel
operators to increase efficiency
• Currently being piloted by Teck
• First prototype in the mining industry
Smart Shovels• Sensors used to separate
ore from waste• Currently employed at
Highland Valley (HVC)• Assessing Red Dog
deployment in 2018
Summary
Excellent Assets & PeopleTeck Energy - a partner of choice; levering our mining leadership
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Fort Hills is the foundation of a premier Canadian oil sands portfolio
#1 priority for Energy is to maximize value from Fort Hills
Energy moves from significant cash outflow to cash inflow by the end of 2018
Energy is consistent with all our strategic criteriaand provides growth options
NotesSlide 5: Quality Barrels in a Progressive Jurisdiction 1. Proved and probable reserves as at December 31, 2017. See Teck’s annual information form dated February 26, 2018 for further information regarding Fort Hills reserves.2. Best estimate of unrisked contingent resources as at December 31, 2017, prepared by an independent qualified resources evaluator. See Teck’s management discussion and
analysis dated February 14, 2018 for further information regarding the Frontier resource. There is uncertainty that it will be commercially viable to produce any portion of the resources.
Slide 10: Lower Carbon Intensity Product at Fort Hills1. Source: IHS Energy Special Report “Comparing GHG Intensity of the Oil Sands and the Average US Crude Oil” May 2014. SCO stands for Synthetic Crude Oil.Slide 11: A Modern Mine Built for Low Cost Operations1. Operating cost estimate represents the Operator’s estimate of costs for the Fort Hills mining and processing operations and do not include the cost of diluent, transportation,
storage and blending. Estimates of Fort Hills operating costs could be negatively affected by delays in or unexpected events involving the ramp up of production. Steady state operations assumes full production of ~90% of nameplate capacity of 194,000 barrels per day.
2. Sustaining cost estimates represent the Operator’s estimate of sustaining costs for the Fort Hills mining and processing operations. Estimates of Fort Hills sustaining costs could be negatively affected by delays in or unexpected events involving the ramp up of production. Fort Hills has a >40 year mine life.
Slide 14: Free Cash Flow for Decades1. Fort Hills’ full production is ~90% of nameplate capacity of 194,000 barrels per day. Includes Crown royalties assuming pre-payout phase. EBITDA is a non-GAAP financial
measure. See “Non-GAAP Financial Measures” slides.Slide 16: Significant Market Presence1. Annualized average at full production. Reflects 21.3% Fort Hills partnership interest. Slide 17: Executing Our Comprehensive Sales & Logistics Strategy1. Annualized average at full production. Reflects 21.3% Fort Hills partnership interest. Slide 18: US Midwest and US Gulf Coast are Key Markets1. Canadian Association of Petroleum Producers, Lee and Doma.Slide 21: Frontier is Another Major Resource1. Best estimate of unrisked contingent resources as at December 31, 2017, prepared by an independent qualified resources evaluator. See Teck’s management discussion and
analysis dated February 14, 2018 for further information regarding the Frontier resource. There is uncertainty that it will be commercially viable to produce any portion of the resources.
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Appendix - EnergyBusiness Unit Modelling
Operating Netback – Q2 2018 (June)
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CAD$/bbl June 1-30, 2018
Bitumen price realized $64.59
Transportation ($8.90)
Crown royalties ($3.59)
Operating costs ($38.25)
Operating netback $13.85
• Operating netback is a non-GAAP measure, presented on a product and sales barrel basis on page 22 of the Q2 2018 news release.
• Derived from the Energy segmented information (P&L), after adjusting for items not directly attributable to the revenues and costs associated with production and delivery.
• Excludes depreciation, taxes and other costs not directly attributable to production and delivery of Fort Hills product.
Blended bitumen sales revenue less diluent expense (includes diluent product, Norlite, East Tank Farm)
Royalties are payable at 1-9% of gross revenue or 25-40% of net revenue depending on project’s financial status. More information on royalties is available at: Alberta Energy
Costs at the mine to produce bitumen: labour, fuel (diesel, natural gas), materials (tools, tires), maintenance, Teck 100% Fort Hills G&A
Downstream of East Tank Farm: Wood Buffalo system, Keystone, Hardisty tank
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East Tank FarmBlending Facility (-)
Edmonton TerminalDiluent Product (-)
Teck
Norlite Pipeline(-)
Wood Buffalo Pipeline
Fort SaskatchewanCavern Storage &
Diluent Product (-)
Teck
Wood Buffalo Pipeline Extension
Keystone Pipeline
Sales - US Gulf Coast (+)
Enbridge MainlineUS Midwest, Eastern Canada
Hardisty Terminal
Rail Loading
Sales – Hardisty (+)
Fort Hills Mine Terminal
FHELP ManagedLegend
Bitumen Price RealizedTransportationOperating Costs
Operating Netback – Q2 2018 (June)
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(C$ in millions, except where noted)One month ended
June 30, 2018Revenue as reported $ 78Less:
Cost of diluent for blending (22)Add back: Crown royalties1 (D) 3Adjusted revenue (A) $ 59
Cost of sales as reported $ 77Less:
Cost of diluent for blending (22)Transportation (C) (8)Depreciation and amortization (12)
Adjusted cash cost of sales (E) $ 35
Blended bitumen barrels sold (000s of barrels) 1,162Less: diluent barrels included in blended bitumen (000s of barrels) (244)Bitumen barrels sold (000s of barrels (B) 918
Operating Netback Reconciliation – Q2 2018 (June)Non-GAAP Financial Measure on page 49 of Q2 2018 news release
1. Revenue is reported after deduction of crown royalties.2. Average period exchange rates are used to convert to US$ per barrel equivalent.
(C$ in millions, except where noted)One month ended
June 30, 2018Per barrel amounts (C$/barrel)
Bitumen price realized (A/B) $64.59Transportation (C/B) (8.90)Crown royalties (D/B) (3.59)Operating costs (E/B) (38.25)
Operating netback (C$/barrel) $ 13.85
Blended Bitumen Price Realized ReconciliationRevenue as reported $ 78Add back: crown royalties1 3Blended bitumen revenue (F) $ 81
Blended bitumen barrels sold (000s of barrels) (G) 1,162Blended bitumen price realized — (CAD$/barrel) (F/G) = H $ 70.00Average exchange rate (I) 1.31Blended bitumen price realized — (US$/barrel) (H/I) $ 53.32
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Energy Gross Profit - Q2 2018 (June)
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Blended Bitumen Revenue Calculation CAD$ in millions June 1-30, 2018
Revenue, as reported (A) $78
Add back: crown royalty (G) – from Q2 2018 news release; page 49 3
Blended bitumen revenue, calculated (H) $81
Energy Business Unit Operating StatementCAD$ in millions June 1-30, 2018
Revenue:
Blend sales (H) $81
Less: crown royalty (G) (3)
Revenue (A) $78
Less: Cost of sales:
Cost of diluent for blending (E) $22
Operating expenses (C) 35
Transportation (D) 8
Depreciation and amortization (F) 12
Cost of sales, calculated $77
Gross profit (B) $1
From Revenue and Gross Profit TableQ2 2018 news release; page 35CAD$ in millions June 1-30, 2018
Revenue (A) $78
Gross profit (loss) (B) $1
From Cost of Sales Summary TableQ2 2018 news release; pages 36-37CAD$ in millions June 1-30, 2018
Operating costs (C) $35
Transportation costs (D) $8
Concentrate and diluent purchases (E) $22
Depreciation and amortization (F) $12
Modelling Bitumen Price Realized – Q2 2018 (June)Non-GAAP Financial Measure
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A. Blend sales = blend sales @ Hardisty + blend sales @ U.S. Gulf Coast (USGC)= $81 per “Blended Bitumen Price Realized Reconciliation” and “Reconciliation of Energy Gross Profit”
• Blend sales @ Hardisty = [(WTI – WTI/WCS differential @ Hardisty – negotiated differential) x F/X rate] x # of barrels sold at Hardisty
• Blend sales @ USGC = [(WTI – WTI/WCS differential @ USGC – negotiated differential) x F/X rate] x # of barrels sold at USGC
***WTI/WCS differentials are not the same at Hardisty vs. USGC
B. Cost of diluent for blending:= Cost of diluent product + diluent transportation/storage + blending cost= $22 per “Cost of Sales Summary Table” and “Reconciliation of Energy Gross Profit”
• Cost of diluent product = [(WTI +/- condensate premium/discount) x # of diluent barrels sold in blend] x F/X rate
***Diluent contained in a barrel of blend ranges from approximately 20% to 25% depending on the quality of blend and season (temperature)• Diluent transportation and blending cost includes tolls on the Norlite pipeline, East Tank Farm blending
facility and diluent storage at Fort Saskatchewan
C. Bitumen barrels sold – as provided on the “Operating Netback Reconciliation”
Bitumen price realized = (blend salesA – diluent expenseB) / bitumen bbls soldC
Energy EBITDA Simplified Model
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Illustrative EBITDA Calculation - Teck Attributable @ 21.3% (14 Mbpd)1
Assumption Per Barrel TotalWTI price US$75.00
Less: Weighted average WTI-WCS differential (US$13.50)Multiplied by: C$/US$ exchange rate @ $1.25WCS price (WTI price less WTI-WCS differential x C$/US$ exchange rate @ $1.25) ~C$77
Less: Operating costs C$20Diluent cost (includes product, diluent transportation and blending costs) C$10Transportation (pipelines & terminalling downstream of ETF) C$7Crown royalties C$3Total cost C$40
EBITDA ~C$37
EBITDA potential (14 Mbpd x cash margin) ~C$520M
Notes: Appendix – Energy Business Unit ModellingSlide 38: Energy EBITDA Simplified Model1. EBITDA is a non-GAAP financial measure. This model is being provided to illustrate how Teck calculates EBITDA for its Energy business unit. The figures included are not
forecasts of projected figures of Teck’s Energy EBITDA. See “Non-GAAP Financial Measures” slides.
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Non-GAAP Financial Measures
Non-GAAP Financial Measures
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EBITDA is profit attributable to shareholders before net finance expense, income and resource taxes, and depreciation and amortization. We believe that disclosing this measureassists readers in understanding the ongoing cash generating potential of our business in order to provide liquidity to fund working capital needs, service outstanding debt, fundfuture capital expenditures and investment opportunities, and pay dividends.
Reconciliation of Teck’s EBITDA and Adjusted EBITDA
(C$ in millions)Six months ended
June 30, 2018Profit attributable to shareholders $ 1,393Finance expense net of finance income 87Provision for income taxes 775Depreciation and amortization 703EBITDA $ 2,958Add (deduct):
Debt repurchase (gains) losses -Debt prepayment option (gains) losses 32Asset sales and provisions 4Foreign exchange (gains) losses (8)Collective agreement charges -Other items (15)
Adjusted EBITDA $ 2,971
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